Numerous useful materials for energy production are found naturally in the earth. For example, fossil fuels (e.g., crude oil, natural gas, and coal) are located as deposits in various rock formations throughout the world, and man has been recovering such materials for many years through mining, drilling, and the like. As more readily obtainable deposits are exhausted, advanced techniques to facilitate the recovery of the useful materials are continually being sought.
As an example, the use of fluids and fluidized mixtures for enhancing the recovery of various fossil fuels has been under development for several years. The mechanisms for enhanced recovery generally are based on enhancing the flow of the fossil fuel through its surrounding geologic formation toward an extraction well. Three predominant mechanisms for enhancing fossil fuel recovery in this manner include the following: 1) using fluids for creating and sustaining fractures in rocky formations to promote more free flow passages; 2) relying on the injection of fluids for volumetric or pressurized displacement of the fossil fuel; and 3) commingling the fluid with the fossil fuel such that one or both of the density and viscosity of the fossil fuel is reduced. Viscosity also may be reduced by mixing other materials into the fossil fuel, by heating the fossil fuel, or both. All of these mechanisms involve injecting material into a well or wells, and then obtaining increased fossil fuel output from the injection well or wells (or from one or more other wells in the vicinity).
Fracturing as a method to enhance fossil fuel recovery typically is done from a wellbore drilled into a reservoir rock formation. A hydraulic fracture can be formed by pumping the fracturing fluid into the wellbore at a rate sufficient to increase the pressure down-hole to a value in excess of the fracture gradient of the formation rock. The pressure causes the formation to crack, allowing the fracturing fluid to enter and extend the crack further into the formation. To keep this fracture open after the injection stops, a solid proppant usually is added to the fracture fluid. The proppant, which is commonly a sieved round sand, is carried into the fracture. This sand is chosen to be higher in permeability than the surrounding formation, and the propped hydraulic fracture then becomes a high permeability conduit through which the formation fluids can flow to the well. A variety of fluids have been proposed and used as fracture fluids, displacement fluids, and viscosity reduction fluids to enhance recovery for fossil fuel reservoirs. Existing methods, however, employ fluids with highly controversial environmental impacts, less than desired effectiveness, or high cost, or a combination of these factors. Some environmental and human health concerns that have been suggested to be associated with fluids typically used in prior art hydraulic fracturing include the potential mishandling of solid toxic waste, potential risks to air quality, potential contamination of ground water, and the unintended migration of gases and hydraulic fracturing chemicals to the surface within a given radius of drilling operations.
Fluids, such as water and steam, with or without surfactants and with or without high heat values, have often shown less than desired performance for enhancing fossil fuel recovery. Key reasons are that water can be much denser than certain fossil fuels, and water is a liquid under equilibrium conditions. Such chemical factors limit or largely eliminate miscibility and mixing between the water/steam and the hydrophobic fossil fuel, thus limiting or largely eliminating any reduction in viscosity of the fossil fuel. The higher density of water can lead to initial physical displacement of the fossil fuel, but this effect is often limited in time and efficiency to an undesirable extent. The denser water may flow downward and away from the fossil fuel reservoir, quickly decreasing or eliminating any displacement effect.
Supercritical carbon dioxide can be highly useful for enhancing oil recovery. Specifically, the supercritical fluid nature and chemical nature of the material causes it to be miscible with oil to lower the viscosity and density of the oil, and/or to improve the oil flow through the formation. Also, the density of supercritical carbon dioxide is substantially lower than the density of water, and it therefore tends to rise into the fossil fuel reservoir rather than to flow downward as does denser water. Furthermore, the material properties of the supercritical CO2 allow it to function as a better solvent for other materials as well. Specifically, as compared to gaseous or liquid CO2, supercritical CO2 exhibit material properties that can substantially increase its dissolution properties. Presently, in order to use supercritical carbon dioxide in recovery methods, the CO2 must be transported from its source (either natural or anthropogenic) to a site of use.
As much as 70% of oil presently in formations is unrecoverable without the use of enhanced oil recovery methods, particularly CO2 led EOR. Despite its potential, there are several limiting factors with EOR in the current art. Primarily, the industrial creation of purified CO2 is overly expensive to separate, purify, and compress in use for EOR as it normally requires large capital and operating investments in the form of system additions, such as amine and/or other solvent scrubbers. Even thereafter, the CO2 must be compressed to a sufficient pressure to inject into the well. These systems are not only expensive and potentially hazardous to the environment, but also require energy, thus limiting the efficiency of the overall system. Secondly, pipeline networks are needed and are not sufficient in the majority of locations where EOR is a possibility, thus limiting its exposure to a significant number of formations. In current instances, pipeline networks have been fed from geologic CO2 sources. However, these are extremely limited in location and amounts of CO2 available.
Moreover, in an economic and political backdrop where CO2 emissions are tightly monitored and always discouraged, it is generally undesirable to open CO2 deposits that already are geologically sequestered.
When fossil fuels are removed from underground deposits using enhanced recovery methods, they often contain dissolved CO2 and other impurities which must be separated using processes such as absorption processes. These can include the following: chemical, physical, and/or solid surface processes; physical separation through membrane or cryogenic means; or hybrid solutions that offer mixed physical and chemical solvents. Such processes may include, but are not limited to, the expensive and inefficient Ryan/Holmes process, the Low-Temperature Separator (LTX) process, the FLUOR amine process, the Selexol process, the Rectisol process, and others. These processes are used to remove the CO2 content of the natural gas separated from liquid oil so that the useful gas fraction (e.g., CH4 fraction) can be produced at a sufficient purity for sale in pipeline systems and so that C2 and greater hydrocarbon fractions can be separated for sale. Moreover, the processes can be used to process flue gas and/or sour gas before it can be transported or re-used. In some instances where the CO2 content is of sufficient quantity (e.g., greater than 30% by weight or partial pressure), the separated CO2 can be recycled for further EOR duty. Specifically, regarding other impurities, natural gas that contains high amounts of hydrogen sulfides (typically an H2S content exceeds 5.7 mg per cubic meter) is known as sour gas, and the H2S must be removed (i.e., so that the natural gas is “sweetened”) using processes such as the amine process or Claus process before injection into pipelines. These impurity removal processes can have detrimental effects on the environment, system efficiency, and overall recovery costs.
Even when CO2 is used for enhanced recovery, the recoverable fossil fuels present in a formation are eventually depleted. The CO2 injection system must then be disassembled and either moved to a new location, which may be very distant, or discontinued and scrapped. This requires the installation of CO2 transmission pipelines with significant permitting, time, and expense requirements. Alternately, the disadvantages of moving CO2 to an injection site still can hinder economical and even successful use of CO2 in an enhanced recovery method for fossil fuel.
There particularly is a need for methods of EOR to be applied to the recovery of very heavy oils, such as oil below about 15 API gravity, bitumen, and tar sands. Heavy oil deposits are often recovered by injection of steam produced from surface steam generators or as pass-out steam from a steam based power generation system. These systems are often old, inefficient and highly polluting, particularly with high CO2 emissions. Accordingly there have been efforts to design a heat generation device which is compact enough to be contained within the well bore and which can combust a fossil fuel within the reservoir producing not only heat but also CO2 and steam which act to displace the heated lower viscosity oil. U.S. Pat. No. 4,397,356 describes a down-hole combustor in which a fuel and an oxidant are burned within a burner which includes a catalytic section to ensure complete combustion with no soot formation, which would block the face of the oil reservoir.
Such efforts, however, still fall short of providing sufficient means for enhancing recovery of a wide variety of formation deposits in a wide variety of settings in a manner that is efficient, economical, environmentally friendly, and easily mobilized for transport to different job sites as needed. Accordingly, there remains a need in the field for further systems and methods for enhancing recovery of formation deposits that not only lessen the impact on the environment but also possibly provide solutions to other existing energy generation issues.